scholarly journals The Impacts of Bedding Strength Parameters on the Micro-Cracking Morphology in Laminated Shale under Uniaxial Compression

2020 ◽  
Vol 10 (16) ◽  
pp. 5496
Author(s):  
Fakai Dou ◽  
Jianguo Wang ◽  
Chunfai Leung
Keyword(s):  
Uniaxial Compression ◽  
Shear Failure ◽  
Critical Role ◽  
Fracture Morphology ◽  
Fracture Network ◽  
Gas Production ◽  
Strength Parameters ◽  
Matrix Cracks ◽  
Shale Formation ◽  
Dominant Matrix

The micro-cracking morphology in laminated shale formation plays a critical role in the enhancement of shale gas production, but the impacts of bedding strength parameters on micro-cracking morphology have not been well understood in laminated shale formation. This paper numerically investigated the initiation and evolution of micro-cracking morphology with bedding strength parameters in laminated shale under uniaxial compression. First, a two-dimensional particle flow model (PFC2D) was established for laminated shale. Then, the micro-mechanical parameters of this model were calibrated using stress-strain curves and final fracture morphology measured in the laboratory. Finally, the impacts of bedding strength parameters on the uniaxial compressive strength (UCS), crack type and the complexity of fracture network were analyzed quantitatively. Numerical simulation results indicate that the UCS of shale varies linearly with the bedding strength, especially when the shear failure of beddings is dominant. Matrix cracks mainly depend on bedding strength, while the generation of tensile cracks is determined by the shear-to-tensile strength ratio of beddings (STR). The shale with a higher STR is likely to produce a more complex fracture network. Therefore, the bedding strength parameters should be carefully evaluated when the initiation and evolution of micro-cracking morphology in laminated shale formation are simulated.

Geomechanical Response Induced by Multiphase (Gas/Water) Flow in the Mallik Hydrate Reservoir of Canada

SPE Journal ◽  
2021 ◽  
pp. 1-18
Author(s):  
Yingli Xia ◽  
Tianfu Xu ◽  
Yilong Yuan ◽  
Xin Xin ◽  
Huixing Zhu
Keyword(s):  
Shear Stress ◽  
Shear Failure ◽  
Energy Resource ◽  
Gas Production ◽  
Production Performance ◽  
Reservoir Model ◽  
Hydrate Reservoir ◽  
Maximum Subsidence ◽  
Permeability Anisotropy

Summary Natural gas hydrate (NGH) is regarded as an important alternative future energy resource. In recent years, a few short-term production tests have been successfully conducted with both permafrost and marine sediments. However, long-term hydrate production performance and the potential geomechanical problems are not very clear. According to the available geological data at the Mallik site, a more realistic hydrate reservoir model that considers the heterogeneity of porosity, permeability, and hydrate saturation was developed and validated by reproducing the field depressurization test. The coupled multiphase and heat flow and geomechanical response induced by depressurization were fully investigated for long-term gas production from the validated hydrate reservoir model. The results indicate that long-term gas production through depressurization from a vertically heterogeneous hydrate reservoir is technically feasible, but the production efficiency is generally modest, with the low average gas production rate of 4.93 × 103 ST m3/d (ST represents the standard conditions) over a 1-year period. The hydrate dissociation region is significantly affected by the reservoir heterogeneity and reveals a heterogeneous dissociation front in the reservoir. The depressurization production results in significant increase of shear stress and vertical compaction in the hydrate reservoir. The response of shear stress indicates that the potential region of sand migration is mainly in the sand-dominant layer during gas production from the hydraulically heterogeneous hydrate reservoir (e.g., sand layers interbedded with clay layers). The maximum subsidence is approximately 78 mm and occurred at the 72nd day, whereas the final subsidence is slowly dropped to 63 mm after 1-year of depressurization production. The vertical subsidence is greatly dependent on the elastic properties and the permeability anisotropy. In particular, the maximum subsidence increased by approximately 81% when the ratio of permeability anisotropy was set at 5:1. Furthermore, the potential shear failure in the hydrate reservoir is strongly correlated to the in-situ stress state. For the normal fault stress regime, the greater the initial horizontal stress is, the less likely the hydrate reservoir is to undergo shear failure during depressurization production.

The Fracture Network Inversion Based on Gas Production Profile

2019 ◽  
Author(s):  
Lidong Mi ◽  
Bicheng Yan ◽  
Qianjun Liu ◽  
Zongxiao Ren
Keyword(s):  
Fracture Network ◽  
Gas Production

scholarly journals Analysis of the Influence of Different Fracture Network Structures on the Production of Shale Gas Reservoirs

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
Ming Yue ◽  
Xiaohe Huang ◽  
Fanmin He ◽  
Lianzhi Yang ◽  
Weiyao Zhu ◽  
...  
Keyword(s):  
Finite Element ◽  
Shale Gas ◽  
Flow Direction ◽  
Fracture Network ◽  
Gas Production ◽  
Low Flow ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
Gas Seepage

Volume fracturing is a key technology in developing unconventional gas reservoirs that contain nano/micron pores. Different fracture structures exert significantly different effects on shale gas production, and a fracture structure can be learned only in a later part of detection. On the basis of a multiscale gas seepage model considering diffusion, slippage, and desorption effects, a three-dimensional finite element algorithm is developed. Two finite element models for different fracture structures for a shale gas reservoir in the Sichuan Basin are established and studied under the condition of equal fracture volumes. One is a tree-like fracture, and the other is a lattice-like fracture. Their effects on the production of a fracture network structure are studied. Numerical results show that under the same condition of equal volumes, the production of the tree-like fracture is higher than that of the lattice-like fracture in the early development period because the angle between fracture branches and the flow direction plays an important role in the seepage of shale gas. In the middle and later periods, owing to a low flow rate, the production of the two structures is nearly similar. Finally, the lattice-like fracture model is regarded as an example to analyze the factors of shale properties that influence shale gas production. The analysis shows that gas production increases along with the diffusion coefficient and matrix permeability. The increase in permeability leads to a larger increase in production, but the decrease in permeability leads to a smaller decrease in production, indicating that the contribution of shale gas production is mainly fracture. The findings of this study can help better understand the influence of different shapes of fractures on the production in a shale gas reservoir.

scholarly journals Fracturing curve and its corresponding gas productivity of coalbed methane wells in the Zhengzhuang block, southern Qinshui Basin, North China

2020 ◽  
Vol 38 (5) ◽  
pp. 1387-1408
Author(s):  
Yang Chen ◽  
Dameng Liu ◽  
Yidong Cai ◽  
Jingjie Yao
Keyword(s):  
Hydraulic Fracturing ◽  
Coalbed Methane ◽  
Continuous Production ◽  
Fracture Morphology ◽  
Geological Structure ◽  
In Situ Stress ◽  
Gas Production ◽  
Type Curves ◽  
Stable Type

Hydraulic fracturing has been widely used in low permeability coalbed methane reservoirs to enhance gas production. To better evaluate the hydraulic fracturing curve and its effect on gas productivity, geological and engineering data of 265 development coalbed methane wells and 14 appraisal coalbed methane wells in the Zhengzhuang block were investigated. Based on the regional geologic research and statistical analysis, the microseismic monitoring results, in-situ stress parameters, and gas productivity were synthetically evaluated. The results show that hydraulic fracturing curves can be divided into four types (descending type, stable type, wavy type, and ascending type) according to the fracturing pressure and fracture morphology, and the distributions of different type curves have direct relationship with geological structure. The vertical in-situ stress is greater than the closure stress in the Zhengzhuang block, but there is anomaly in the aggregation areas of the wavy and ascending fracturing curves, which is the main reason for the development of multi-directional propagated fractures. The fracture azimuth is consistent with the regional maximum principle in-situ stress direction (NE–NEE direction). Furthermore, the 265 fracturing curves indicate that the coalbed methane wells owned descending, and stable-type fracturing curves possibly have better fracturing effect considering the propagation pressure gradient (FP) and instantaneous shut-in pressure (PISI). Two fracturing-productivity patterns are summarized according to 61 continuous production wells with different fracturing type and their plane distribution, which indicates that the fracturing effect of different fracturing curve follows the pattern: descending type > stable type > wavy type > ascending type.

scholarly journals Experimental Investigation of Spontaneous Imbibition of Water into Hydrate Sediments Using Nuclear Magnetic Resonance Method

Energies ◽  
2020 ◽  
Vol 13 (2) ◽  
pp. 445 ◽  
Author(s):  
Liu Yang ◽  
Chuanqing Zhang ◽  
Jianchao Cai ◽  
Hongfeng Lu
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Research Work ◽  
Resonance Method ◽  
Fracture Network ◽  
Gas Production ◽  
Spontaneous Imbibition ◽  
Nuclear Magnetic Resonance Method ◽  
Water Imbibition ◽  
Nuclear Magnetic

Field observations show that less than one percent of dissociation water can be produced during gas hydrate production, resulting from spontaneous water imbibition into matrix pores. What’s more, the hydrate sediments are easily dispersed in water, and it is difficult to carry out spontaneous imbibition experiments. At present, there is little research work on the imbibition capacity of hydrate sediments. In this paper, a new method of water imbibition is proposed for hydrate sediments, and nuclear magnetic resonance (NMR) technique is used to monitor water migration. The results show that as the imbibition time increases, the water is gradually imbibed into matrix pores. Water imbibition can cause dramatic changes in pore structure, such as microfracture initiation, fracture network generation and skeleton dispersion. When the imbibition time exceeds a critical value, many secondary pores (new large pores and micro-fractures) start to appear. When imbibition time exceeds the dispersion time, fracture networks are generated, eventually leading to dispersion of the sediment skeleton. The imbibition curves of hydrate sediments can be divided into two linear stages, which corresponds, respectively, to water imbibition of primary pores and secondary pores. The imbibition rate of secondary pores is significantly larger than that of primary pores, indicating that the generation of new fractures can greatly accelerate the imbibition rate. Research on the characteristics of water imbibition in hydrate sediments is important for optimizing hydrate production regime and increasing natural gas production.

scholarly journals The Key Factors That Determine the Economically Viable, Horizontal Hydrofractured Gas Wells in Mudrocks

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2348 ◽  
Author(s):  
Syed Haider ◽  
Wardana Saputra ◽  
Tadeusz Patzek
Keyword(s):  
Gas Flow ◽  
Horizontal Well ◽  
Source Term ◽  
Organic Matrix ◽  
Fracture Network ◽  
Gas Production ◽  
Fracture Permeability ◽  
Gas Wells ◽  
Stimulated Reservoir Volume ◽  
Well Production

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity.

scholarly journals Mechanical Properties and Acoustic Emission Characteristics of Karst Limestone under Uniaxial Compression

2018 ◽  
Vol 2018 ◽  
pp. 1-14 ◽  
Author(s):  
Jianxun Chen ◽  
Qingsong Wang ◽  
Jiaqi Guo ◽  
Yanbin Luo ◽  
Yao Li ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Acoustic Emission ◽  
Water Content ◽  
Uniaxial Compression ◽  
Wave Velocity ◽  
Brittle Failure ◽  
Shear Failure ◽  
Testing Machine ◽  
Natural State ◽  
Saturated State

Firstly, I-RPT ultrasonic detector was used to test the wave velocity of karst limestone with different initial microstructure and water content. Then, RMT-150B rock testing machine and DS2-16B acoustic emission system were used to test the acoustic emission (AE) under uniaxial compression. Mechanical properties and AE characteristics were obtained during rock failure. The detailed relationship between stress-strain and AE characteristics was studied in this paper. Research results indicated the following: (1) For samples with many primary fissures and defects, wave velocity in dry state was larger than that in its natural state. From natural state to saturated state, the wave velocity tended to increase. For samples with good integrity, wave velocity increased with increasing of water content. (2) In the dry state, the samples presented tension failure. In saturated state, the samples presented tension-shear failure. For samples with cracks and good integrity, samples showed brittle failure. For samples with many corrosion pores which showed ductile damage under natural and saturated state, the spalling phenomenon was enhanced under saturated state. (3) With increasing of water content, the peak stress and AE peak reduced dramatically. In brittle failure, AE peak could be considered a sign of failure. In ductile failure, AE activity decreased gradually with the decrease of stress. (4) The mechanical properties and AE characteristics corresponding to four main fracture propagation types were also discussed.

Evaluation of Induced Thermal Pressurization in Clearwater Shale Caprock in Electromagnetic Steam-Assisted Gravity-Drainage Projects

SPE Journal ◽  
2013 ◽  
Vol 19 (03) ◽  
pp. 443-462 ◽  
Author(s):  
Sahar Ghannadi ◽  
Mazda Irani ◽  
Rick Chalaturnyk
Keyword(s):  
Pore Pressure ◽  
Analytical Solutions ◽  
Oil Sands ◽  
Shear Failure ◽  
Gravity Drainage ◽  
Hydraulic Fractures ◽  
Low Permeability ◽  
Steam Assisted Gravity Drainage ◽  
Thermal Pressurization ◽  
Shale Formation

Summary Inductive methods, such as electromagnetic steam-assisted gravity drainage (EM-SAGD), have been identified as technically and economically feasible recovery methods for shallow oil-sands reservoirs with overburdens of more than 30 m (Koolman et al. 2008). However, in EM-SAGD projects, the caprock overlying oil-sands reservoirs is also electromagnetically heated along with the bitumen reservoir. Because permeability is low in Alberta thermal-project caprock formations (i.e., the Clearwater shale formation in the Athabasca deposit and the Colorado shale formation in the Cold Lake deposit), the pore pressure resulting from the thermal expansion of pore fluids may not be balanced with the fluid loss caused by flow and the fluid-volume changes resulting from pore dilation. In extreme cases, the water boils, and the pore pressure increases dramatically as a result of the phase change in the water, which causes profound effective-stress reduction. After this condition is established, pore pressure increases can lead to shear failure of the caprock, the creation of microcracks and hydraulic fractures, and subsequent caprock integrity failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from the reservoir, making them more resistant to shear failure (Collins 2005, 2007). In cases of induced thermal pressurization, low-permeability caprocks are not always more resistant. In this study, analytical solutions are obtained for temperature and pore-pressure rises caused by the constant EM heating rate of the caprock. These analytical solutions show that pore-pressure increases from EM heating depend on the permeability and compressibility of the caprock formation. For stiff or low-compressibility media, thermal pressurization can cause fluid pressures to approach hydrostatic pressure, and shear strength to approach zero for low-cohesive-strength units of the caprock (units of the caprock with high silt and sand percentage) and sections of the caprock with pre-existing fractures with no cohesion.

scholarly journals X-Ray Microtomography (μCT) as a Useful Tool for Visualization and Interpretation of Shear Strength Test Results

2015 ◽  
Vol 36 (4) ◽  
pp. 47-55 ◽  
Author(s):  
Damian Stefaniuk ◽  
Matylda Tankiewicz ◽  
Joanna Stróżyk
Keyword(s):  
Shear Strength ◽  
Shear Failure ◽  
Triaxial Compression ◽  
Soil Testing ◽  
Geometrical Parameters ◽  
Clayey Soils ◽  
Test Results ◽  
Strength Parameters ◽  
X Ray ◽  
Method Of Evaluation

Abstract The paper demonstrates the applicability of X-ray microtomography (ìCT) to analysis of the results of shear strength examinations of clayey soils. The method of X-ray three-dimensional imaging offers new possibilities in soil testing. The work focuses on a non-destructive method of evaluation of specimen quality used in shear tests and mechanical behavior of soil. The paper presents the results of examination of 4 selected clayey soils. Specimens prepared for the triaxial test have been scanned using ìCT before and after the triaxial compression tests. The shear strength parameters of the soils have been estimated. Changes in soil structure caused by compression and shear failure have been presented as visualizations of the samples tested. This allowed for improved interpretation and evaluation of soil strength parameters and recognition of pre-existing fissures and the exact mode of failure. Basic geometrical parameters have been determined for selected cross-sections of specimens after failure. The test results indicate the utility of the method applied in soil testing.

scholarly journals Numerical Study on the Effects of Imbibition on Gas Production and Shut-In Time Optimization in Woodford Shale Formation

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3222 ◽  
Author(s):  
Zhou Zhou ◽  
Shiming Wei ◽  
Rong Lu ◽  
Xiaopeng Li
Keyword(s):  
Numerical Model ◽  
Hydraulic Fracturing ◽  
Field Data ◽  
Gas Production ◽  
Model Parameters ◽  
Water Recovery ◽  
Woodford Shale ◽  
Capillary Suction ◽  
Shale Formation ◽  
The Relationship

In shale gas formations, imbibition is significant since the tight pore structure causes a strong capillary suction pressure. After hydraulic fracturing, imbibition during the period of shut-in affects the water recovery of flowback. Although there have been many studies investigating imbibition in shale formations, few papers have studied the relationship between gas production and shut-in time under the influence of imbibition. This paper developed a numerical model to investigate the effect of imbibition on gas production to optimize the shut-in time after hydraulic fracturing. This numerical model is a 2-D two-phase (gas and water) imbibition model for simulating an imbibed fluid flow and its effect on permeability, flowback, and water recovery. The experimental and field data from the Woodford shale formation were matched by the model to properly configure and calibrate the model parameters. The experimental data consisted of the relationship between the imbibed fluid volume and permeability change, the relative permeability, and the capillary pressure for the Woodford shale samples. The Woodford field data included the gas production and flowback volume. The modeling results indicate that imbibition can be a beneficial factor for gas production, since it can increase rock permeability. However, the gas production would be reduced when excessive fluid is imbibed by the shale matrix. Therefore, the shut-in time after hydraulic fracturing, when the imbibition happens in shale, could be optimized to maximize the gas production.

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